Controller for monitoring fluid flow volume

ABSTRACT

A system, method and program for calculating a fluid flow volume within a conduit having an operably connected flow meter is disclosed. The system includes a controller having a backplane. A flow meter module is operably connected to the backplane of the controller and to the flow meter. A program embedded within the controller is also operably connected to the flow meter. The program includes a plurality of segments for sensing a characteristic of the fluid for determining the flow volume of the fluid. The controller, in cooperation with the flow meter module, monitors the dynamic fluid density of the fluid in the conduit. The controller utilizes the dynamic density to determine a correction factor to more accurately calculate the fluid flow volume through the conduit.

RELATED APPLICATIONS

[0001] This patent application is a continuation-in-part claimingbenefit to, and incorporating by reference, U.S. patent application Ser.No. 09/784,375, filed Feb. 15, 2001 and entitled, “FLOW METER MODULE FORA CONTROLLER,” (Attorney Docket No. SAA-66, 401 P 258).

DESCRIPTION

[0002] The present invention generally relates to a method, system, andprogram for monitoring and controlling a fluid transportation system.More specifically, the present invention is directed to a mediumreadable by a programmable device. The medium being operably connectedto a controller for monitoring and controlling a fluid flow volume in afluid transportation system.

BACKGROUND OF THE INVENTION

[0003] The production, transportation and sale of energy sources hasalways required some form of measurement to determine the quantityproduced, bought, or sold. The accuracy and reliability of a system thatmeasures an energy source, i.e., gas and liquid, is extremely importantto the buyers and sellers involved. A seemingly insignificant errorwithin the measuring system can result in a large monetary loss.

[0004] Technological advances in the areas of fluid flow metering andcomputation has led to improved accuracy and reliability. Some of theseadvances have been made in the area of metering, or measuring,transported energy products. These advances have also focused on factorssuch as safety, reliability and standardization.

[0005] Today's metering and transfer system involves more than simplymeasuring fluid flow; it can also involve extensive electronics,software, communication interfaces, analysis, and control. Measuringfluid flow can involve multiple turbine meters with energy flowcomputers, densitometers, gas chromatography, meter proving systems andRTU or SCADA interfaces.

[0006] Measurement and control of energy sources are valuable processesfor companies producing and transporting theses energy sources. Manygovernments, organizations and industries have enacted standards andregulations related to recovering, refining, distributing, and sellingof oil and oil by-products, i.e., gasoline, kerosene, butane, ethanol,etc. The energy resource industry has various standards and regulationsto ensure the accuracy and safety of transporting and metering theseenergy sources.

[0007] The process of transporting a fluid energy source, e.g., oil,through a pipeline is monitored and controlled with the assistance of acombination of sensors and process computers. Generally, a computerprocessor monitors several aspects, e.g., fluid flow volume, of the oiltransportation. The control of the equipment facilitating thetransportation of oil is generally performed by environmentally robustdevices such as a controller. The controller regulates valves, tanks,and scales without requiring an individual to constantly interact withthe system.

[0008] A very important aspect of a fluid transportation system involvesthe fluid flow meter utilized to monitor the amount of oil delivered toa customer. Because of the vast amounts of fluid delivered, the accuracyof the fluid flow meter must be ensured at regular intervals. Aninaccurate fluid flow meter can result in overcharging or undercharginga customer for the delivered product. An inaccurate flow metering systemcan result in significant amounts of unpaid products, i.e., shrinkage.

[0009] A turbine flow meter is an accurate and reliable flow meter forboth liquid and gas volumetric flow. Some applications utilizing aturbine flow meter involve water, natural gas, oil, petrochemicals,beverages, aerospace, and medical supplies. The turbine comprises arotor having a plurality of blades mounted across the flow direction ofthe fluid. The diameter of the rotor is slightly less than the innerdiameter of a conduit, and its speed of rotation is proportional to thevolumetric flow volume through the conduit. Turbine rotation can bedetected by solid state devices or mechanical sensors.

[0010] In one application utilizing a variable reluctance coil pick-up,i.e., a permanent magnet, turbine blades are made of a materialattracted to the magnet. As each blade of the turbine passes the coil, avoltage pulse is generated in the coil. Each pulse represents a discretevolume of liquid. The number of pulses per unit volume is called themeter's K-factor.

[0011] In another application utilizing inductance pick-up, a permanentmagnet is embedded in the rotor. As each blade passes the coil, avoltage pulse is generated. Alternatively, only one blade is magneticand the pulse represents a complete revolution of the rotor. Dependingupon the design, it may be preferable to amplify the output signal priorto its transmission.

[0012] The accuracy of a turbine flow meter partially depends uponproving the fluid flow meter and the ability to provide correctionfactors to compensate for meter inaccuracies caused by damage to themeter or surrounding environmental conditions. At a minimum, a typicalflow computer utilizes the following industrial standard volume flowequations to determine the correction factors. The American PetroleumInstitute defines the API 2540 standard to determine flow of liquidhydrocarbons that includes the following techniques: meter proving;correction for temperature, density (fluid gravity) and pressure of thefluid flowing; pulse interpolation; pulse fidelity; correction for thetemperature and pressure of the conduit material (typically steel); andaudit trails and report specifications. The American Society for Testing& Materials that defines the ASTM D1250 and the American NationalStandards Institute that defines the ANSI D1250 standard have adopted,in their respective industry segments, the API 2540 standards. TheAmerican Petroleum Institute also defines a M factor used to correct forthe loss of turbine accuracy. Over time, the turbine becomes lessaccurate due to wear and tear; and the M factor—a dimensionlessnumber—incorporated into the API 2540 equations adjusts for turbineinaccuracy. API 2540, ASTM D1250 and ANSI D1250 are expresslyincorporated herein by reference.

[0013] Proving the fluid flow meter is a process for ensuring theaccuracy and reliability of the flow meter. Typically, a section of thefluid system called a proving loop is utilized during the meter proving.The dimensions of the proving loop are known and the flow of fluidwithin the loop can be monitored by sensors wherein a variety of fluidcharacteristics can be sensed. The meter proving process simultaneouslymonitors a pulse signal generated by a turbine operably connected withinthe fluid system. The flow volume of the fluid is determined byutilizing the sensed values of the fluid's characteristics with theindustrial standard flow volume equations. The calculated flow volume isthen compared to the known flow volume of the proving loop. By comparingthe calculated fluid flow volume to the known fluid flow volume of theproving loop, the accuracy of the flow meter can be determined.

[0014] Generally, the duration of a meter proving process isapproximately one hundred thousand turbine pulses. This amount of timeis believed to be adequate to accurately determine the fluid flowvolume. Often times, the turbine pulse signal is not in synch with theflow meter proving process, i.e., generally the meter proving processwill not start at the beginning of the turbine pulse signal. When thepulses are counted at the end of the proving period, the partial pulsesoccurring at the beginning and end of the proving period are omitted.Because of the duration of the proving period, it is generally believedthat these partial pulses are negligible. However, utilizing the partialpulses and other characteristics of the fluid and conduit, the timerequired for the meter proving process can be reduced.

[0015] This invention is directed to solving these and other problems.

SUMMARY OF THE INVENTION

[0016] The present invention is directed to utilizing a software programoperable within a controller to monitor a flow volume in a fluidtransportation system. The software interacts with the controller, e.g.,programmable logic controller (PLC), and an operably connected flowmeter to sense a characteristic of the fluid for calculating the fluidflow volume of the liquid. The sensed characteristic of the fluid, e.g.,temperature, density, and pressure; is utilized by the software programto determine correction factors to be incorporated with industrialstandard equations. The software program also includes an interpolationmethod for any partially sensed revolutions of the flow meter occurringduring a meter proving process. The software program provides correctionfactors to the flow meter via the controller and its turbine metermodule. The supplied correction factors adjust the flow meter for anyinaccuracies; thereby, reducing product shrinkage. The resultantcorrection factors, in communication with the turbine meter card,provide a less expensive implementation for controlling and monitoring afluid transportation system without the need of a separate fluid flowcomputer.

[0017] One embodiment of the present invention is directed to a systemfor calculating a flow volume of a fluid within a conduit having anoperably connected flow meter. The system comprises a programmable logiccontroller having a backplane. A flow meter module is operably connectedto the backplane of the programmable logic controller and to the flowmeter. A program operably connected within the programmable logiccontroller includes a plurality of segments for cooperating with theflow meter to sense a characteristic of the fluid. Data received fromthe flow meter is utilized by the program to calculate the flow volumeof the fluid within the conduit.

[0018] In a further aspect of the present invention, the fluidcharacteristic sensed by the flow meter is temperature, pressure, and/ordensity. The sensed characteristic is utilized by the controller toprovide a real-time update of an industrial correction factor whereinthe computation of the fluid flow volume is adjusted in response to thesensed characteristic. Alternatively, characteristics of the conduit canalso be monitored and utilized by the controller to provide real-timeupdates of the industrial correction factor.

[0019] A further embodiment of the present invention is directed to amethod of measuring a flow volume of a fluid within a conduit. Acontroller is connected to a flow meter and the conduit. The controllermonitors the fluid flow volume through a plurality of input channelsoperably connected to the flow meter of a fluid transportation system.The controller senses a pulse signal generated by the flow meter over apredetermined time frame. A densitometer operably connected to thecontroller senses the real time density of the fluid. The sensed densityis stored by the controller as a dynamic variable to be utilized in thedetermination of the flow volume. The controller utilizes the senseddynamic density in cooperation with the standard industrial equations,AGA-7/API 2540, for calculating a flow volume.

[0020] In another embodiment of the present invention, a medium forcalculating a flow volume of a fluid within a conduit is disclosed. Themedium is readable by a programmable logic controller being operablyconnected to a flow meter and a conduit. The medium includes a programcomprising several segments cooperating to determine the flow volume ofa fluid. A first segment obtains a characteristic of the fluid. Thecharacteristic being temperature, pressure, and/or density. A secondsegment utilizes an industrial standard equation, API 2540, to calculatea correction factor in response to the sensed fluid characteristic. Anda third segment calculates a meter correction factor in response to ameter proving.

[0021] Another embodiment of the present invention is directed to amethod of proving a flow meter. The flow meter is connected to acontroller and a proving loop within a fluid transportation system. Theproving loop has a known flow volume. The controller monitors a fluidflow within the proving loop. The method comprises the steps of startinga meter proving period and sensing a pulse signal responsive to a flowmeter. The flow meter generates a fluid flow through the fluidtransportation system. The meter proving process is terminated and theamount of sensed pulse signals occurring during the meter proving periodis calculated. The fluid flow volume of the proving loop is determinedin response to the pulse signals occurring during the meter provingprocess and other sensed characteristics of the fluid and conduit,preferably density and temperature. The calculated flow volume of theproving loop is compared against the known volume of the proving loop.

[0022] A further aspect of the above embodiment of the present inventionis directed to adjusting the flow meter and/or controller in response tothe comparison of the calculated flow volume of the proving loop and itsknown flow volume, wherein the fluid flow meter and/or controller moreaccurately calculate the flow volume.

[0023] An object of the present invention is to utilize standardindustrial equations embedded within the programmable logic controller,rather than incorporated within a remote I/O device such as a flowcomputer, to reduce the time and cost of meter proving and to improvethe accuracy when calculating the fluid flow rate of a liquid within aconduit. The use of frequently updated correction factors with the meterflow equations improves the accuracy and reliability of the flow meter.The controller senses real-time process variables, e.g., fluid andconduit characteristics used in the standard flow equations, andcalculates a more accurate correction factor. Because the programmablelogic controller monitoring and controlling the metering processutilizes the correction factor more frequently, shrinkage will bereduced.

[0024] Cost savings are obtained because the programmable logiccontroller replaces the flow computer, as a remote I/O device. Removingthe flow computer as an I/O device from the already present PLC reducescost and inaccuracy. In place of the flow computer, the system usesexisting I/O to measure characteristics, such as, density, temperatureand pressure of the flowing fluid and of the conduit materialencapsulating the fluid. The PLC adds flexibility becausecharacteristics affecting the fluid (stated above in this paragraph) areresident in the memory of the PLC. Other features of the PLC such asprocessing speed; tables containing standards; and remote web access canbe added without difficulty. Moreover, the PLC can store past values tohelp ensure repeatability already inherent in a fixed, stable systemthat a PLC offers. In addition, more accurate flow volume calculationscan be obtained by utilizing additional characteristics of the fluid andconduit, i.e., real time density, temperature, and pressure values, incooperation with the industrial standard equations of API 2540/AGA-7.

[0025] Other advantages and aspects of the present invention will becomeapparent upon reading the following description of the drawings anddetailed description of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

[0026]FIG. 1 is diagram depicting one embodiment of a turbine flowmeter;

[0027]FIG. 2 is a diagram depicting another embodiment of a turbine flowmeter;

[0028]FIG. 3 is a block diagram of one embodiment of the presentinvention:

[0029]FIG. 3A is a block diagram of an embodiment of a proving loop usedwith the present invention;

[0030]FIG. 4 is a block diagram of another embodiment of the presentinvention;

[0031]FIG. 5 is a timing diagram of the interpolation method of thepresent invention;

[0032]FIG. 6A is a flow chart showing a process for measuring fluid flowutilizing a single meter run;

[0033]FIG. 6B is a flow chart showing a process for counting pulsesduring the fluid flow measurement process;

[0034]FIG. 7A is a flow chart showing a process for meter provingutilizing a single meter run; and,

[0035]FIG. 7B is a flow chart showing a process for counting pulsesduring the meter proving process.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

[0036] While this invention is susceptible of embodiments in manydifferent forms, there is shown in the drawings and will be hereindescribed in detail a preferred embodiment of the invention with theunderstanding that the present disclosure is to be considered as anexemplification of the principles of the invention and is not intendedto limit the broad aspect of the invention.

[0037] In one application of the present invention, a flow meter 10,preferably a turbine, comprises a rotor 12 having a plurality of blades14 mounted across the flow direction of the fluid within a conduit 16.See FIGS. 1 and 2. The diameter of the rotor 12 is slightly less thanthe inner diameter of the conduit 16, or pipe, and its speed of rotationis proportional to the volumetric flow of the fluid. Turbine rotationcan be detected by solid state devices or mechanical sensors. As eachblade 14 revolves, a voltage pulse is generated. Each pulse represents adiscrete volume of liquid. Alternatively, only one blade 14 can generatea pulse, thus, each pulse represents one complete revolution of therotor 12. The number of pulses per unit volume is called the meter'sK-factor.

[0038] The rate of rotation and registration of each rotor blade 14implies the passage of a fixed volume of fluid. Fluid flow in a pipelineis the actual volume of fluid that passes a given point during aspecified time. Volumetric flow can be calculated by monitoring variouscharacteristics of the fluid, such as velocity, temperature, density,and pressure. These characteristics are sensed by a controller 20 foruse with industrial standard equations for fluid flow calculation,preferably in accordance with AGA-7 and API 2540 standards.

[0039] A controller 20 having a flow meter module 22 operably attachedto the backplane 23 of the controller, is operably connected to the flowmeter 10 via a plurality of input channels 25, i.e., I₁, I₂, I₃, etc.The pulse signal generated by the turbine 10 is received by the flowmeter module 22. The input channels of the flow meter module 22 areadapted to receive input signals in the range of 25 mV-30V DC. Thus, theflow meter module 22 can be directly connected to the flow meter 10. Theflow meter module 22 receives the flow meter frequency signal and can beprogrammed with K and M factors for converting the frequency input to aspecified volumetric flow volume measurement unit. Typical units ofvolumetric flow include gallons (or liters) per minute and cubic feet(or meters) per minute. The M factor is a dimensionless numbercorrecting for accuracy loss over the life of the turbine meter, formwear and tear. The K factor is defined as “pulses per unit volume.”Other meters generating pulses, such as a Corolis meter, and a positivedisplacement meter can be used in place of the flow meter 10.

[0040] A more accurate fluid flow volume can be calculated by utilizingthe real-time fluid density of the fluid in cooperation with theindustrial standard equations. See FIG. 4. For example, a densitometer24 is operably connected to an input channel 25 of the controller 20.The densitometer 24 senses the density of the fluid within the pipeline16. The densitometer 24 outputs either a frequency (linearized by theprogrammable logic controller (PLC)) or a 4-20 mA output into the PLC,which represents a real-time sensed density; used by the API 2540standard equations Chapter 21, incorporated herein by reference. Thereal-time sensed density value is utilized with AGA-7/API 2540 standardto calculate the flow volume. Preferably, the real-time sensed densityvalues are stored as a dynamic variable within the flow meter module 22.Utilizing dynamic density values with the dual chronometry pulseinterpolation standard equation of API 2540 takes into account theeffects that changing pressure and temperature of the fluid (and thematerial of the conduit 16 itself) will have on the calculated flowvolume. The use of the dynamic density values provides for a moreaccurate flow volume than a flow volume calculated with a static densityvariable for a fluid having an assumed temperature and pressure value.

[0041] Referring to FIGS. 6A and 6B, flow charts 100, 101 show thepreferred method of calculating the fluid flow volume of a flow meter.The operator configures the flow meter 10 by providing various operatingparameters to the controller 102, e.g., type of liquid, i.e., premiumgasoline, crude oil, etc.; density; etc. The controller 10 receivespulse data through the turbine meter module 104. Depending upon theconfiguration of the flow meter 10, multiple input channels 25 can beutilized to sense pulses generated by the flow meter. To further ensuredata received through the input channels 25, the operator can elect toutilize the Fidelity algorithm 106 provided in API 2540. The Fidelityalgorithm 106 compares the pulse data received on the input channels 25and confirms the reliability of the pulses generated by the flow meter10.

[0042] Independent of the execution of Fidelity algorithm 106, theoperator can select to interpolate the pulses generated by the flowmeter 108. The calculation of the sensed pulse signals is the sum of thefull pulse signals and the partial pulse signals occurring during thefluid flow measurement process. The partial pulse signals areinterpolated to provide an accurate pulse signal measurement. Thecontroller utilizes API standard 2540 Chapter 4 equations to interpolatethe sensed signals for determining the partial pulses. The partialpulses are added to the full pulses to more accurately determine thefluid flow volume. Regardless of whether pulse interpolation isconducted, the incoming pulses are counted and a meter frequency iscalculated 110. The pulse count is then transmitted to the programmablelogic controller for fluid flow computation 112.

[0043] Along with the accumulated pulse date and calculated meterfrequency, several variables can be utilized to more accuratelycalculate the fluid flow volume. Preferably, these variables arecharacteristics of the fluid being measured. For instance, temperature114, pressure 116, and density 118 of the liquid can be sensed orprovided. Additionally, the temperature of the conduit 16 can also beconsidered. In response to these characteristics, a correction factorfor temperature (CTL) 120, and pressure and compressibility (CPL) 122can be calculated and utilized to more accurately determine the fluidflow volume. CTL is determined by utilizing API 2540 Tables 5, 6, 23,24, 53, 54, 59, and 60. CPL is determined through API 2540, Chapter11.2.1/M for hydrocarbons: 638-1074 Kg/m³. An operation log of the metercan also be taken into account based on a past meter proving 124.

[0044] Sediment and water volume can be determined 126 under API 2540Chapter 12, Section 2, Part 1.10.4. Through the use of the calculatedcorrection factors, the gross 128 and net 130 fluid flow rates and thegross and net barrels can be determined using API 2540 Chapter 12,Section 2, Part 1.10.2 and 1.10.3, respectively 112, 114.

[0045] In another embodiment of the present invention, the controllerexecutes a meter proving process by measuring the quantity of fluid flowthrough a proving loop of known volume. Proving the fluid flow meter 10is a process for ensuring the accuracy and reliability of the flowmeter. The flow volume of the fluid is determined by utilizing thesensed characteristics of the fluid (and conduit) with industrialstandard flow volume equations, e.g., AGA-7/ API 2540 standards.

[0046] See FIGS. 3 and 3A. Typically, a section of the pipeline 16called a proving loop 26 is utilized during the meter proving. Thedimensions of the proving loop 26 are known and the flow of fluidthrough the loop can be monitored by sensors wherein a variety of fluidcharacteristics can be sensed. The number of meter pulses are convertedto a volume unit of measure. The calculated flow quantity is thencompared to the known flow volume of the meter proving loop 26 toprovide an error measurement on the flow meter 16.

[0047] The controller 20 signals the proving loop to start its provingprocess. The controller receives a first signal from the proving loopindicating the start. The controller receives a second signal from theproving loop indicating the end. Between the first and second signals,the controller 20 senses the number of meter pulses.

[0048] During the meter proving process, the controller 20 senses theamount of pulse signals generated by a turbine 10 that occurred. Thecontroller utilizes a calculator 30 to calculate the a fluid volume forthe proving loop 26 in response to the sensed pulse signals thatoccurred during the meter proving process. By comparing the calculatedfluid flow volume to the known fluid flow volume of the proving loop 26,one can determine the accuracy of the flow meter 10.

[0049] The proving loop 26 is a U-shaped conduit having a known fluidvolume. FIG. 3A. The proving loop 26 is operably attached to the fluidtransportation system. A pair of valves V1, V2 connect the ends of theproving loop 26 to the system. At the start of the meter provingprocess, the valves are switched to allow fluid into the proving loop26. The fluid entering the proving loop 26 pushes a ball, e.g., pig,through the proving loop. Initially, the ball passes and activates afirst switch, S1 27. Upon activation of the first switch, S1 27, thecontroller 20 senses the pulses generated by the flow meter 10 until themeter proving process is terminated when the ball passes a secondswitch, S2 29. The time it takes the ball to travel from the firstswitch, S1 27, to the second switch, S2 29, is the duration of the meterproving period.

[0050] During the meter proving process, the flow meter module 22 sensesthe density of the fluid flowing in the proving loop 26. The senseddensity values are linearized by the controller 20. Actual values can beused from a table stored within the controller 20. The controller 20utilizes the linearized density value and the amount of pulses sensedduring the meter proving process to calculate a correction factor, M, tolater be used by a program,—preferably residing in the memory of thecontroller—for determining the volume of fluid flowing through thetransportation fluid system. The M correction factor is utilized inequation AGA-7 to determine the accuracy of the flow meter 10 in thesystem. The accuracy of the flow meter 10 can be improved by adjustingthe flow meter or the calculations, used to determine the fluid flowvolume.

[0051] Other characteristics of the fluid can be utilized to obtain amore accurate calculation of the fluid flow volume. The controller iscapable of sensing the temperature and pressure of the fluid flowingthrough the conduit 16. The program adjusts the fluid density fortemperature, pressure, and compressibility of the fluid. The programutilizes the repetitively sensed and adjusted fluid density values toupdate the measured volume during meter proving.

[0052] Generally, the turbine pulse signal 18 is not in synch with theflow meter 10 proving process, i.e., the meter proving process willgenerally not start at the beginning of the turbine pulse signal 18.FIG. 5. Thus, partial pulses 18 occur at the beginning and end of theproving period. An interpolator 32 utilizes a pulse interpolation methodto improve the discrimination of the flow meter's output, thus requiringa lesser amount of pulse signals to be collected during the meterproving process. Because fewer pulse signals 18 are required, theproving loop 26 can be shortened, thus reducing the cost of the fluidtransportation system.

[0053] While various interpolation methods can be used, the preferableinterpolation method utilized by the controller 20 is the doublechronometry method of API 2540. Double chronometry pulse interpolationrequires counting a total integral number of flow meter pulses, Nm,generated during the proving process and measuring a set of timeintervals, T1 and T2. FIG. 5. T1 is the time interval between the firstpulse before or after the first detection signal and the first pulsebefore or after the last detection signal. T2 is the time intervalbetween the first and last detector pulses.

[0054] The pulse monitor 34 is started and stopped by a meter proverdetector 28. The time intervals T1 and T2 correspond to Nm pulses andthe interpolated number of pulses, N1, respectively. The interpolatedpulse count, N1, is equal to Nm(T2/T1). An accumulator 36 sums andstores the total number of pulse signals for use by the controller 10 indetermining flow volume. The total number of pulses is the sum of theintegral pulses and the interpolated partial pulses.

[0055] Referring to FIGS. 7A and 7B, flow charts 200, 201 depict thepreferred method of meter proving for a single flow meter. Similar tothe method of calculating a fluid flow volume 100, 101, an operatorconfigures the controller 10 by providing operating parameters, e.g.,type of liquid, density, etc. to the controller 202. The meter provingprocess is begun and the ball trips the first detector 204. If more thanone pulse counter 21 is being implemented during the meter provingprocess, data from each channel is compared using the Fidelity algorithm206 provided in API 2540. Similar to the flow measurement processdiscussed earlier, the pulse interpolation of API 2540 can be performedat this point if the option is selected by the operator 208. Once thedetector switch is closed, a proving algorithm is begun and the pulsesare counted 210. The counted pulses are transmitted to the backplane 23of the programmable logic controller 10 for flow calculations 212. Thepulse whole count and pulse fractional count is calculated 214 andconverted 216 to a volume and the converted volume is compared to theknown volume.

[0056] Various characteristics of the fluid and the conduit can beutilized to more accurately conduct the meter proving process wherein acorrection factor is implemented with standard equations for improvingthe determination of fluid flow. The temperature of the fluid is sensedand a correction factor, CTL, is calculated 218 using API 2540 Tables 5,6, 23, 24, 53, 54, 59, and 60. The pressure of the fluid is sensed 220and a correction factor, CPL, is calculated using API 2540 Chapter11.2.1/M Compressibility Factors for Hydrocarbons: 638-1075 Kg/m³. Thetemperature 222 and pressure 224 of the steel proving tube 26 is sensedand correction factors, CTS and CPS, respectively, are calculated usingAPI 2540 Chapter 12.

[0057] Past performance of the flow meter 10 can also be considered andutilized to more accurately determine a fluid flow rate 226. A meterfactor is calculated based on the last meter proving run using API 2540Chapters 4 and 12. If the correction-adjusted measurement volume isdifferent than the last meter proving run, the meter factor can beautomatically added to the equation or can be stored for manual entry ata later time 228.

[0058] While the specific embodiment has been illustrated and described,numerous modifications come to mind without significantly departing fromthe spirit of the invention, and the scope of protection is only limitedby the scope of the accompanying claims.

I claim:
 1. A system for calculating a fluid flow volume within aconduit having an operably connected flow meter, the system comprising:a controller having a backplane; a flow meter module being operablyconnected to the backplane of the controller and to the flow meter; and,a program readable by the controller for determining the flow volume ofthe fluid, the program having a plurality of segments being operablyconnected to the flow meter for sensing a characteristic of the fluid.2. The system of claim 1 further comprising: a plurality of inputchannels being operably connected between the backplane and the flowmeter wherein the controller interfaces directly with the flow meterwithout the need for signal conversion.
 3. The system of claim 2 whereinthe characteristic of the fluid is selected from a group consisting oftemperature, pressure, and density.
 4. The system of claim 2 wherein theflow meter module is embedded in the backplane of the controller.
 5. Thesystem of claim 2 wherein the flow meter includes a densitometer, thedensitometer being operably connected to the controller for sensing areal-time density of the fluid wherein the sensed density is utilized bythe program to determine the fluid flow volume.
 6. The system of claim 2wherein the program is embedded in the controller.
 7. The system ofclaim 2 wherein the plurality of input channels are selected from thegroup consisting of pulse, positive displacement, and rotary to pulseoutput meters.
 8. A medium for calculating a flow volume of a fluidwithin a conduit, the medium being readable by a controller, thecontroller including a backplane and a flow meter module, the controllerbeing operably connected to a flow meter, the flow meter being operablyconnected to the conduit, the medium comprising: a first segment forobtaining pulse data from the flow meter; a second segment for obtainingtemperature data of the fluid; a third segment for obtaining densitydata of the fluid; a fourth segment for obtaining pressure data of thefluid; a fifth segment for calculating a correction factor fortemperature, CTL, the calculation utilizing API 2540 Tables 5, 6, 23,24, 53, 54, 59, and 60; and, a sixth segment for calculating acorrection factor for pressure and compressibility, CPL, the calculationutilizing API 2540 Chapter 11.2.1/M Compressibility Factors forHydrocarbons: 638-1074 Kg/m³.
 9. The medium of claim 8 furthercomprising: a seventh segment for calculating a meter factor responsiveto a last meter proving run, the meter factor calculation utilizing API2540 Chapter
 4. 10. The medium of claim 8 further comprising: an eighthsegment for calculating a sediment and water volume, the sediment andwater volume calculation utilizing API 2540 Chapter 12, section 2, part1.10.4.
 11. The medium of claim 10 further comprising: a ninth segmentfor calculating a gross flow rate, the gross flow rate calculationutilizing API 2540 Chapter 12, section 2, part 1.10.2.
 12. The medium ofclaim 11 further comprising: a tenth segment for calculating a net flowrate, the net flow rate calculation utilizing API 2540 Chapter 12,section 2, part 1.10.2.
 13. The medium of claim 12 further comprising:an eleventh segment for calculating a gross barrel, the gross barrelcalculation utilizing API 2540 chapter 12 section 12 part 1.10.3. 14.The medium of claim 13 further comprising: a twelfth segment forcalculating a net barrel, the net barrel calculation utilizing API 2540chapter 12 section 12 part 1.10.3.
 15. The medium of claim 8 furthercomprising: a thirteenth segment for obtaining flow configurationparameters.
 16. The medium of claim 8 wherein the first segment forobtaining pulse data comprises: a count segment for counting incomingpulses and calculating a flow meter frequency; an accumulation segmentfor accumulating the pulse count; and, a transmit segment fortransmitting the pulse count to the controller.
 17. A medium for provinga flow meter, the medium being readable by a controller, the controllerincluding a backplane and a flow meter module, the controller beingoperably connected to a flow meter, the flow meter being operablyconnected to a conduit, the medium comprising: a first segment forreading a detector switch of a proving loop, the proving loop beingoperably connected to the flow meter; a second segment for obtaining apulse data from the flow meter; a third segment for converting the pulsedata to a volume and comparing the volume to a known volume; a fourthsegment for calculating a correction factor for temperature, CTL, thecalculation utilizing API 2540 Tables 5, 6, 23, 24, 53, 54, 59, and 60;a fifth segment for calculating a correction factor for pressure andcompressibility, CPL, the calculation utilizing API 2540 Chapter11.2.1/M Compressibility Factors for Hydrocarbons: 638-1074 Kg/m³; asixth segment for calculating the effect of temperature on the conduit,CTS, the calculation utilizing API 2540 Chapter 12; a seventh segmentfor calculating the effect of pressure on the conduit, CPS, thecalculation utilizing API 2540 Chapter 12; and, an eighth segment forcalculating a meter factor responsive to a last meter proving run, themeter factor calculation utilizing API 2540 Chapters 4 and
 12. 18. Themedium of claim 17 further comprising: a ninth segment for obtainingproving configuration parameters.
 19. The medium of claim 17 wherein thesecond segment for obtaining pulse data comprises: a count segment forcounting incoming pulses and calculating a flow meter frequency; and, atransmit segment for transmitting a pulse count to the controller.